A conventional means of separating gas, oil and water is using a three-phase separator. However, field experience indicates that many of these systems experience significant liquid carry-over which has resulted in problems and damage of downstream facilities like the gas compressions. To mitigate this, an additional polishing scrubber is generally provided downstream of the bulk gas/liquid or gas, oil and water separators. This adds to space, weight and instrumentation (due to additional level monitoring and control) which in turn results in increased cost. The reliability, availability and maintainability of the system are also reduced due to the additional equipment and associated instrumentation.
For facilities where the inlet fluid is from a pipeline, slug flow in the pipeline results in significant sloshing, liquid entrainment and a drastic change in liquid level at the inlet separator. This turbulence at the inlet separator may result in a significant amount of liquid collecting around the gas outlet device at the separator. This, in turn, will result in both high liquid entrainment into the gas stream out of the separator and also potential blockage of the separator outlet device particularly if the liquid is waxy.
The blockages occur as a result of cold spots at the gas outlet device; with the effect made worse by the normally small flow path associated with the internals. “Sloshing” of the liquid phase may also lead to liquid coming into contact with the gas outlet device. For separators on a Floating Production Storage and Unloading Unit (FPSO), this is more pronounced as the ship's motion leads to greater movement of the liquid phase. If the liquid entrained in the gas stream is waxy, there is no means of removing the wax that builds up at the device unless the separator is taken offline, and the outlet device disassembled.
The need for high efficiency separation of the gas from the entrained liquids, for most applications, results in highly efficient gas outlet devices, or internals, being required at the separator. These internals may be mist mats, vane packs, cyclonic devices or other proprietary internals. However to accommodate the gas outlet device within the separator, the vapor space in the separator needs to be large enough to accommodate the device. This increases the size of the separator.
In particular, waxy crude that forms gel or crystalline structure at lower temperatures normally leads to a number of operational problems especially the ability of the fluid to flow and clogging of the instruments and internals that is integral to the performance of the equipment.
For facilities that handle waxy crude it is ubiquitous to inject Pour Point Depressant (PPD) to lower the pour point temperatures, and to maintain high production fluid temperatures in the equipments, pipes and instruments that handles the waxy crude. However it is unavoidable that some cold spots will develop within the system. These cold spots are located within the equipment or pipeline that experiences temperatures lower than the bulk fluid temperature. These cold spots are more prevalent in the gas phase where the specific heat of the gas is low. Low specific heat means that the gas gains or loses temperature faster.
The separation chamber, which receives the production fluid, is typically a three phase separator that carries out course separation of the production fluid into its individual phases. The problem of wax is compounded within all such separation, as the gas phase internals are normally built into the inlet separator and consists of small flow paths and parts, and further, with the gas phase in direct contact with the oil phase. Also, it has been found that slugging, or surges, lead to more liquids carryover in the gas phase.
For specific FPSO applications, the motion of the vessel may make the above problem worse.
Furthermore, there is no means for early detection of the waxing problems, and no means to fix the problem online if the wax begins to form.
And when wax begins to form, the problem is self propagating. Typically to mitigate liquid carry-over problems, a downstream gas scrubber is provided with liquid collected pumped back to the separator. This however increases the space and weight requirements and in addition increases the control, operational & maintenance complexity of the system.
A further problem involves slugging which is a challenging problem for many crude oil production receiving facilities particularly those receiving production from multi-phase subsea pipelines as they are susceptible to slugs. This is particularly the case for production facilities receiving crude and associated gas from remote wells via pipelines and risers. Slugs generated in the pipelines and risers not only require processing facilities to be increased in size to accommodate the slugs, but also results in production upsets associated with the high speed at which the slugs arrive and the transient pressure fluctuations due to the surge of gas following the arrival of the slug. Under these scenarios the production facilities like inlet heat exchangers, production separators and downstream gas compressors generally will not be able to cope with this transient slugging phenomenon resulting in production upsets and possibly shutdown.
Slugging results in the compression of the gas phase behind a slug. The transportation of a slug requires a larger pressure behind the slug to keep the slug moving through the pipeline and riser. This pressure increase depends on the size of the liquid slug. After the slug arrives at the outlet of the pipeline or production platform, the compressed gas creates a large gas surge, which again may result in major upsets in topside facilities, like the downstream gas compression trains.
The production from the remote wells, usually comprising large slug volumes is transported to the heat exchanger via pipelines or risers. Without any effective separation upstream, the slug flow conditions at the heater results in large heating duties of the exchanger as both the gas stream and the liquid streams are heated. The excessive heating duties results in poor performance of the heat exchanger, thus waxy crude and emulsions are still of existence in the outlet stream. Furthermore, the system experiences large pressure drop as the heating duty is high.
On the other hand, the existence of waxy crude and emulsions will cause blockages at the inlet and outlets of the separator. Although the separation of oil, gas and water can be performed, the exiting gas stream will comprise significant liquid entrainment that will cause damage to the condensing system, resulting in system shutdown. Hence, the reliability of the separator system is very low. In addition, these turbulences and the ineffective heating of the inlet fluids leading to the presence of water emulsion, inherent with multiphase fluids under slugging conditions will also result improper oil water separation in the separator. This will require the downstream system to be upsized due to excessive water carry-over in oil stream and excessive oil carry-over in the water stream.
Furthermore, the presence of sand in the production fluid often results in sand build-up in the downstream separator which in turn possibly requires frequent shutdowns to remove sand from the separator or requires sand removal devices to be installed at the separator which are expensive.